In known oil extraction techniques, gas is injected into a tube of crude oil to lift the oil up the tube where the oil reservoir pressure itself is insufficient to do so, or to increase the oil flow rate further. This technique is often referred to as “gas lift”. Pressured gas is supplied to the annulus between the outside well-bore casing and the inner production tubing string and injected into the base of the liquid column in the tubing string through a down-hole gas lift valve. The effect is to aerate the crude oil, reducing its density and causing the resultant gas/oil mixture to flow up the tubing.
A known form of gas lift oil well configuration is depicted schematically in FIG. 1. Pressurized gas is supplied by a compressor station 2 to an injection gas manifold 4. The manifold splits the gas supply into four separate feeds for respective wells 6. Each well includes an outer well-bore casing 8 surrounding an inner production tubing string or pipe 10. The gas is fed into the annulus 12 defined between the casing and tubing string. The gas is then injected into the tubing string close to its base via a gas lift valve 14.
Crude oil 16 is drawn up the tubing string and mixes with the injected gas as the mixture is lifted upwards. The mixture is fed out of the well head 16 to a production manifold 18 where it is combined with the supplies of the other wells 6. The combined mixture is fed to gas/oil separator 20. Here, the injected gas is separated from the oil and fed to compressor station 2 for re-compression and re-injection. The extracted oil is fed to storage 22, before onward supply along pipeline 24.
The amount of gas to be injected into a particular well to maximise oil production varies according to a number of factors, such as the well conditions and geometries. The liquid protection rate will also vary depending on the viscosity of the extracted liquid and the geographical location of the well itself. A graph illustrating a typical relationship between gas injection rate and liquid production rate is shown in FIG. 2. This form of graph is commonly referred to as a “gas lift performance curve”, and is generated on the basis of a constant injection pressure of the gas. Too much or too little injected gas will result in deviation from the most efficient production state. The primary aim of optimization is to ensure that lift gas is applied to each individual well at a rate which achieves the maximum production from the field, whilst minimising the consumption of compressed gas. In the example shown, the production rate is optimized at a gas injection rate of around 0.9 MMscf/d (million standard cubic feet per day) and a gas injection valve orifice size would be selected accordingly.
In existing gas lift configurations, the gas lift valve has an orifice diameter selected to maximise production from a given well based on the gas pressure supplied to the well. However, if circumstances change and a different gas flow rate is desired to optimize production, it is necessary to halt production before the orifice can be replaced by one of the desired diameter. An “unloading” procedure must then be carried out to resume production.
Unloading the well-bore is a laborious process, as will be apparent from the following discussion with reference to FIGS. 3A to 3C. Several gas injection valves are used to provide different pressure-controlled stages to sequentially remove static fluid from the annulus during gas lift start-up. In addition to gas lift valve 14, the well-bore depicted has unloading valves 30,32. Initially, the injection pressure depresses the liquid level in the annulus between the outer well-bore casing 8 and the inner production tubing string 10, flushing out the annulus 12 until valve 30 is uncovered as shown in FIG. 3B. At this point, gas is injected in to the inner tubing 10 via valve 30, decreasing the tubing pressure. As the inner tubing pressure drops, the liquid level in the annulus 12 also drops. At the point where valve 32 is uncovered as shown in FIG. 3C, gas is injected into the inner tubing 10 via valve 32 and valve 30 is shut off. This continues until the unloading process is completed.
In practice, the unloading and gas lift valves are often provided in side mandrels, as shown in FIG. 4. Each mandrel 40 is usually formed with the tubing string deployed in a well-bore using “kick-over” tools to physically deform the sidewall of the tubing, which is itself a time-consuming and difficult procedure. Each valve 30, 32 and 14 is installed in a respective mandrel 40. A packer 42 is provided at the base of the annulus 12 and acts as a seal between the oil producing rock formation surrounding the well-bore, the casing 8 and the tubing 10 to prevent gas from entering the producing zone.
To change the orifice size of the gas lift valve 14, it is necessary to terminate gas injection and halt oil production. Slick line trips are used to change the gas lift valve and replace it with one having a different orifice diameter. To resume gas injection, the unloading process is repeated.
It will be appreciated that any modification to existing configurations will need to be able to survive a long time (typically 5 to 10 years) in very harsh conditions underground, at depths of around 1 km or more. The ambient pressure will be very high (200 bar or more) and high temperatures are likely to be experienced.